Process for generating hydrogen from heavy oil or hydrocarbons

ABSTRACT

The present invention provides a steam reforming process for heavy oil or hydrocarbons using a circulating fluidized bed reactor, the process having a reforming step and a regeneration step, wherein the reforming step and the regeneration step comprise a bubbling fluidized reactor containing a fluidizable nickel-containing reforming catalyst and produce hydrogen as a product of the reforming bed. The API gravity of the feedstock may be between −11 and 54, preferably between −11 and 20. The present invention also provides a fluidized bed hydrocarbon steam reforming process using a regenerable catalyst to produce hydrogen, wherein a circulating bed reactor is operated in an alternating manner, switching between two steps: reforming and regeneration; using a mixture of a fluidizable solid and a fluidizable nickel-containing reforming catalyst; producing hydrogen as a product of the reforming step with a minimum hydrogen content of 25 volume percent, preferably at least 60 volume % and more preferably at least 70 volume percent on a dry weight basis.

CROSS REFERENCE TO RELATED APPLICATIONS

The present application claims the benefit of the provisionalapplication No. 61/985,279 filed Apr. 28, 2014 (titled PROCESS FORGENERATING HYDROGEN FROM HEAVY OIL OR HYDROCABONS, by Girish Srinivas,Steven Charles Gebhard and Robert James Copland), which is incorporatedby reference herein. Provisional application No. 61/985,279 is notadmitted to be prior art with respect to the present invention by itsmention in the background or cross reference section.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

This invention was made using U.S. government funding through the U.S.Department of Energy contract No. DE-FG02-08ER85135. The government hascertain rights in this invention

BACKGROUND

Refineries in the U.S. are processing increasingly heavy sour crudesthat contain metals, sulfur, and high molecular weight aromatichydrocarbons. Many sour crudes originate in the Western Hemisphere,including heavy crudes from Venezuela, Southern California, and theenormous quantities of oil sands in Canada. Processing and upgradingthese heavy feedstocks requires considerable hydrogen. Since revampingor installing new hydrogen capacity with conventional technologies suchas steam methane reforming, or petroleum coke gasification, are usuallyexpensive, developing a process that can generate hydrogen from “bottomof the barrel” products presents an economically attractive alternative.

Currently, refiners make at least part of the hydrogen they use bysteam-reforming methane or coke gasification. Naphtha is the heaviestfeed that can economically be processed by conventional steam-reforming,and existing methods suffer from the limitation that heavy oils are notsuitable as the feedstock.

Furthermore, hydrogen usage by petroleum refiners has been increasing.Approximately half of the petroleum refined in the United States isimported, and approximately half of that can be classified as heavycrude that contains high concentrations of sulfur, metals and highmolecular weight hydrocarbons. Sulfur, metals and other contaminants areremoved by hydrotreating, and high molecular weight hydrocarbons can beconverted into lower molecular weight fractions by hydroprocessing. Veryhigh molecular weight components such as asphaltenes are usuallyprocessed by coking. The reduction in allowable aromatic hydrocarbonsand sulfur in gasoline and diesel, along with the need to processheavier crude oils, has increased the demand for hydrogen in therefinery.

The main commercial processes for the on-purpose production of hydrogenare steam reforming (natural gas or naphtha), partial oxidation (coal,coke, resid), or electrolysis of water. [Kirk-Othmer Encyclopedia ofChemical Technology, in Hydrogen by William F. Baade, Uday N. Parekh,Venkat S. Raman, Dec. 20, 2001, John Wiley & Sons.] Hydrogen is alsocommercially produced as a by-product of chemical processes (ethylenecrackers, styrene, MTBE etc.) or gasoline manufacturing (catalyticreforming). Conventional steam reforming is a method for hydrogenproduction from hydrocarbon fuels such as natural gas. This is achievedin a processing device called a reformer which reacts steam at hightemperature with the hydrocarbon fuel.

Scheme 1: Methane Steam ReformingCH₄+2H₂O→CO₂+4H₂

Heavy oil (for example resid) and solids (coal) are used in oxidation orgasification processes to make hydrogen.

Scheme 2: Resid Partial Oxidation and Coal Gasificationresid partial oxidation: CH_(1.8)+0.98H₂O+0.51O₂→CO₂+1.88H₂coal gasification: CH_(0.8)+0.6H₂O+0.7O₂→CO₂+H₂

Selection of the differing processes is dependent on a number ofcriteria: (1) the availability and relative cost of the differentfeedstocks; (2) capital costs; (3) operating costs; (4) environmentalconsiderations, and (5) end use of the hydrogen or syngas. Generally, asthe feedstocks go from natural gas to light hydrocarbons to heavyhydrocarbons and then to solid feedstocks, the processing difficulty andcapital costs increase. Partial oxidation (PDX) plants also require anair separation plant to produce the oxygen, larger water gas shift andCO₂ removal facilities and gas cleanup systems due to impurities presentin the solid feedstocks (such as sulfur) (Kirk-Othmer, 2001).

Heavier fractions, such as vacuum residue, deasphalter bottoms, refinerysludges, and petroleum coke, can be processed into hydrogen using PDXtechnology, however, the low hydrogen content of these feeds combinedwith a high capital and operating cost requires that they be availableat very low or negative cost for a hydrogen only facility (Kirk-Othmer,2001).

In the U.S., over 95% of on-purpose hydrogen production is supplied bysteam methane reforming of light hydrocarbons. Many existing refineryand chemical hydrogen plants produce a medium-purity (95%-97%) hydrogenproduct by removing the carbon dioxide in an absorption system andmethanating any remaining carbon oxides. Since the 1980s most SMRs usepressure swing adsorption (PSA) technology to recover and purify thehydrogen to purities above 99.9% (Kirk-Othmer, 2001).

When natural gas is used as the feed to a steam reformer, the basicreactions are (1) reforming and (2) shift.

Scheme 3:

Reforming

CH₄+H₂O→←CO+3H₂ Endothermic ΔH° 25° C.=206 KJ/gmol (49.3 kcal/gmol)

Shift

CO+H₂O→←CO₂+H₂ Exothermic ΔH° 25° C.=−41 KJ/gmol (−9.8 kcal/gmol)

The reforming reaction is highly endothermic and accompanied by anincrease in the total number of moles. Hence, it is favored by hightemperature and low pressure. For light hydrocarbon feeds such asnatural gas, a single nickel-based catalyst is employed. However, forheavier feeds such as naphtha, two catalysts are usually preferred(Kirk-Othmer, 2001). The reforming reaction is equilibrium-limited. Itis favored by high temperature 788-880° C., low pressure (1.4-3.8 MPa),and a high steam-to-carbon ratio (2.5 to 4). These conditions minimizemethane slip at the reformed outlet and yield an equilibrium mixturethat is rich in hydrogen. The shift reaction is exothermic andindependent of pressure. It is also equilibrium limited and favored bylow temperature (343-371° C.) and high steam concentration. Normally,the shift catalyst is based on iron oxide.

It is clear that a steam reformer has the capability to also producecarbon dioxide (CO₂), carbon monoxide (CO) and synthesis gas (CO+H₂),which are valuable coproducts in some geographic areas. Also owing tothe high temperatures, varying amounts of steam must be generated byheat recovery from the reformer furnace. This steam can be exported tothe refinery or petrochemical facility for process needs and/orconverted into electricity. By-products such as carbon dioxide, steam,and electricity have a large impact on plant design and economics. Inaddition, other utilities such as boiler feed water, cooling water,instrument air, and nitrogen are required to support operation of ahydrogen plant. Hence the needs can be combined with those of the hostsite to further reduce the total system supply costs.

Heavy oil is produced in the refining of petroleum and can come fromother sources including but not limited to the mining and extraction ofoil sands. Examples of fossil sources of heavy oil include atmospherictower bottoms, vacuum tower bottoms, oil sands and bitumen. Heavy oilcan also be contained in pyrolysis oil made from biomass.

Chemical looping steam reforming processes use a metal catalyst thatcycles from the metal oxide to the reduced form in two separate reactorvessels. These processes are limited to light gasses or lighthydrocarbons (Lyon, 2007).

Reforming processes in general are limited to light hydrocarbonfeedstocks because heavy oil feedstocks produce excessive coke, solidsor viscous liquids that physically block the packed bed reactor.Moderately heavy feedstocks like naphtha require two catalysts.Reforming processes are also limited by high-sulfur feedstocks: thesulfur reacts with the reforming catalyst, for example a nickelcatalyst, and deactivates it.

There remains a need in the art for a steam reforming process that canconvert low-value heavy oil, such as atmospheric tower bottoms, vacuumtower bottoms, oil sands, bitumen oil and biomass pyrolysis oil, intohydrogen, a higher value feedstock that has many uses in the refineryand in other applications. There also remains a need in the art for aprocess to produce hydrogen from heavy oil that does not suffer fromirreversible catalyst deactivation, either from irreversible cokeformation or sulfur poisoning. Existing processes such as gasificationare very high temperature and capital intensive processes and thereremains a need in the art for a hydrogen production process from heavyoil that uses lower temperatures than gasification, which operates at orabove about 1100° C.

BRIEF SUMMARY OF THE INVENTION

The present invention is directed to a process that satisfies the needto produce hydrogen from heavy oil feedstocks. In the specification andthe attached drawings and various views of the invention the process maybe referred to as HyRes or the HyRes process. As this term implies theprocess can produce hydrogen (Hy) from residuum (Res), and similar heavyoil feedstocks. The process comprises a reforming process that convertsheavy oil, for example but not limited to heavy tower bottoms, vacuumtower bottoms, residuum, pyrolysis oil, to a hydrogen-rich syngas. Theprocess of the present invention solves limitations in existingprocesses by allowing the continuous production of hydrogen (or syngas)with a solid catalyst while avoiding deactivation, reactor plugging, orirreversible coke formation on the catalyst surface when usingproblematic heavy oil feedstocks. The process also produces a superiorhydrogen or syngas product stream because it is very low in nitrogen asa result of the process not requiring any added air in the reformingbed. The process of the present invention transports oxygen to thereforming bed in the form of NiO (nickel oxide) that is produced in theregeneration bed. The undiluted syngas from the present invention has ahigher value than syngas mixed with nitrogen (air). For example, thecomposition of syngas produced by an air blown coal gasifier is 60% N₂,12% CO, 9% CO₂, 1.5% CH₄ and 10% H₂. In contrast, the syngas from thisinvention typically contains no nitrogen, 8% CO, 21% CO₂, <1% CH₄ and70% H₂. The process uses a mixture of a fluidizable reforming catalystmixed with another high crush strength fluidizable solid material. Thenickel-based reforming catalyst must also have certain physicalproperties that are described in greater detail in this application,which allow this process to operate continuously without the problemsdescribed in the BACKGROUND. An aspect of this process is a combinationof the nickel-based catalyst with appropriate physical properties andthe alpha-alumina as a solid diluent. This solid mixture makes theprocess operate continuously, while avoiding irreversible coke build-upon the catalyst when using heavy oil feedstocks. The mixture is alsomore economical than using a pure nickel catalyst solid composition.

The process produces hydrogen in refineries at a cost that isconsiderably lower than hydrogen produced from conventional technologiesor purchasing hydrogen from a third party. This technology converts“bottom of the barrel” residuum into hydrogen. In the process residuumis steam reformed over nickel based catalysts to produce hydrogenwithout catalyst deactivation and without the need for an oxygen plant;this greatly expands the range of feedstocks that can be used togenerate hydrogen. The process can steam reform residuum over nickelbased catalysts without catalyst deactivation because the system uses afluidized bed with periodic catalyst regeneration with air.

The process can use atmospheric tower bottoms (ATB) various grades ofvacuum tower bottoms (VTB). VTB samples are generally solids at roomtemperature. A medium VTB can be heated to be able to feed it into thelaboratory reactor, and a heavy VTB had to be cut with 20% xylene andheated to a pumpable liquid melt. With ATB, it was possible to operatewith steam-to-carbon (S/C) ratios as low as about 3 without catalystdeactivation. VTB feeds required operating with a steam/carbon ratio ofabout 5, which is the same steam to carbon ratio needed with muchlighter feeds such as natural gas and petroleum naphtha when usingconventional fixed bed reformers; thus, the present invention is capableof processing heavy feedstocks without the need to generate more steamthan would be required for a conventional light hydrocarbon steamreformer Catalyst deactivation is avoided with a ATB or a VTB feedstock.

An embodiment of the invention is a heavy oil steam reforming process toproduce hydrogen, the process comprising: providing a heavy oilfeedstock; providing a steam feedstock; providing a fuel feedstock;providing an air feedstock; providing at least one circulating fluidizedbed reactor; providing a fluidizable nickel-containing reformingcatalyst; using the fluidizable nickel-containing reforming catalyst ina reforming step in a bubbling fluidized reaction, wherein the reformingstep is performed at about 865 to 900° C. and a pressure of about 50 to100 psig; using the fluidizable nickel-containing reforming catalyst ina regeneration step in a bubbling fluidized reaction, wherein theregeneration step is performed at about 865 to 900° C. and at a pressureof about 50 to 100 psig; allowing the fluidizable nickel-containingreforming catalyst to contact the heavy oil feedstock and the steamfeedstock in the reforming step, wherein the reforming step is operatedunder conditions such that the product of the weight hourly spacevelocity (WHSV) of the heavy oil feedstock and the time online equalsfrom 0.001 to 10; allowing the fluidizable mixture to contact the airfeedstock and the fuel feedstock in the regeneration step to removesulfur and carbon buildup; repeatedly cycling the fluidizablenickel-containing reforming catalyst between the reforming step and theregeneration step; and, producing hydrogen as a product of the reformingstep.

An embodiment of the invention is a heavy oil steam reforming process toproduce hydrogen, the process comprising: providing a heavy oilfeedstock; providing a steam feedstock; providing a fuel feedstock;providing an air feedstock; providing a circulating fluidized bedreactor, the circulating fluidized bed reactor having a reforming bedand a regeneration bed, wherein the reforming bed and the regenerationbed are operably connected to each other; providing a mixture of afluidizable solid, for example alpha-alumina, spinel, and the like beingsubstantially inert, with a high melting temperature (higher thanoperating conditions—for example not silica) and physically hard orotherwise having resistance to attrition, and a fluidizablenickel-containing reforming catalyst, wherein, the nickel-containingreforming catalyst has a nickel content of from 10-20 weight percent ona magnesium aluminate support, a particle size from 63 to 225 um;operating the circulating fluidized bed reactor with the reforming bedat about 865 to 870° C. and the regeneration bed at about 865 to 900°C., wherein the pressure of the circulating fluidized bed reactor isabout 50 to 100 psig, and allowing the mixture of fluidizablealpha-alumina and the fluidizable nickel-containing catalyst to contacta mixture of the heavy oil feedstock and the steam feedstock in thereforming bed from about 90 to 120 minutes, and; producing hydrogen as aproduct of the reforming bed.

Optionally, in an embodiment the fluidizable nickel-containing reformingcatalyst is from 25 to 75 weight percent of the mixture of fluidizablealpha-alumina and fluidizable nickel-containing reforming catalyst.

In a further embodiment the fluidizable nickel-containing reformingcatalyst is about 25 weight percent of the mixture of fluidizablealpha-alumina and fluidizable nickel-containing reforming catalyst.

In a further embodiment the fluidizable nickel-containing reformingcatalyst is about 50 weight percent of the mixture of fluidizablealpha-alumina and fluidizable nickel-containing reforming catalyst.

In a further embodiment the fluidizable nickel-containing reformingcatalyst is about 75 weight percent of the mixture of fluidizablealpha-alumina and fluidizable nickel-containing reforming catalyst.

In an embodiment the fuel feedstock in the process may be petcoke.

In an optional embodiment the process further comprises transporting themixture of a fluidizable solid and the fluidizable nickel-containingcatalyst with coke and sulfur build-up from the reforming bed to theregeneration bed, and supplying to the regeneration bed the fuelfeedstock and the air feedstock to remove coke and sulfur from themixture of fluidizable alpha-alumina and the fluidizablenickel-containing catalyst, the sulfur removed in the form of sulfurdioxide, and the average contact time for the mixture of fluidizablealpha-alumina and fluidizable nickel-containing reforming catalyst inthe regeneration bed is about 40 to 60 minutes.

In a further embodiment the process comprises converting thenickel-containing catalyst to the nickel-oxide form in the regenerationbed and allowing the mixture of fluidizable alpha-alumina and thefluidizable nickel-containing catalyst to transport to the reforming bedin a continuous looping process.

In another embodiment the process comprises generating a synthesis gasproduct stream with at least 25 (more preferably at least 60) volume %hydrogen and at most 1 (more preferably at most 0.5) volume % nitrogen.

In another embodiment the process comprises operating the circulatingfluidized bed reactor with essentially no supplemental oxygen for thereforming bed, other than the oxygen transported in the form ofnickel-oxide from the regeneration bed and oxygen contained in the steamfeedstock and in the heavy oil feedstock.

In yet another embodiment the process further comprises operating thereforming bed with an S/C ratio between about 1.5 and 13.6,alternatively a from about 3 to about 5, or alternatively greater thanabout 1.

In preferred embodiments the heavy oil is atmospheric tower bottoms(also called long residuum or atmospheric residuum), or alternativelyvacuum tower bottoms (also called vacuum residuum).

Another embodiment is a fluidized bed heavy oil steam reforming processusing a regenerable catalyst to produce hydrogen, the processcomprising: providing a hydrocarbon feedstock that has an API gravitybetween −11 and +54 (tar sand bitumen to heavy naphtha); providing asteam feedstock; providing a fuel feedstock (hydrocarbon feedstock orpetroleum coke); providing an air feedstock; providing a circulatingfluidized bed reactor, the circulating fluidized bed reactor having areforming bed and a regeneration bed, wherein the reforming bed and theregeneration bed are operably connected to each other; providing amixture of a fluidizable solid (for example, alpha-alumina) and afluidizable nickel-containing reforming catalyst; operating thecirculating fluidized bed reactor with the reforming bed at about 865 to870° C. and the regeneration bed at about 865 to 900° C., the systempressure at about 50 to 100 psig, and allowing the mixture offluidizable solid (alpha-alumina) and the fluidizable nickel-containingcatalyst to contact a mixture of the hydrocarbon feedstock and the steamfeedstock in the reforming bed for a period of time such that theproduct of the weight hourly space velocity (WHSV) and the time onlineequals from 0.001 to 10, preferably 0.01 to 1.64 and more preferably0.01 to 0.25; allowing the mixture of fluidizable alpha-alumina and thefluidizable nickel-containing catalyst with coke and sulfur build-upfrom the reforming bed to transport to the regeneration bed, andsupplying to the regeneration bed the fuel feedstock and the airfeedstock to remove coke and sulfur from the mixture of fluidizablealpha-alumina and the fluidizable nickel-containing catalyst; convertingthe nickel-containing catalyst to the nickel-oxide form in theregeneration bed and allowing the mixture of fluidizable alpha-aluminaand the fluidizable nickel-containing catalyst to transport to thereforming bed in a continuous looping process; generating a synthesisgas product stream with at least 25 volume % (more preferably 60 volume%) hydrogen and at most 1.0 volume % (more preferably 0.5 volume %)nitrogen; operating the circulating fluidized bed reactor withessentially no supplemental oxygen for the reforming bed, other than theoxygen transported in the form of nickel-oxide from the regeneration bedand oxygen contained in the steam feedstock and in the heavy oilfeedstock; operating the reforming bed with an S/C ratio between about1.5 and 13.6, wherein, the nickel-containing reforming catalyst has anickel content of from 10-20 weight percent, a magnesium aluminatesupport, a particle size from 63 to 225 um, and; producing hydrogen as aproduct of the reforming bed.

In further embodiments the fluidizable nickel-containing reformingcatalyst is from 25 to 75 weight percent of the mixture of fluidizablealpha-alumina and fluidizable nickel-containing reforming catalyst, andthe S/C ratio is from about 3 to about 5.

In a preferred embodiment the heavy oil is selected from the groupconsisting of atmospheric tower bottoms, medium vacuum tower bottom, andheavy vacuum tower bottoms.

Another embodiment is a fluidized bed hydrocarbon steam reformingprocess using a regenerable catalyst to produce hydrogen, the processcomprising: providing a hydrocarbon feedstock that has an API gravitybetween −11 and +54; providing a steam feedstock; providing a fuelfeedstock; providing an air feedstock; providing a circulating fluidizedbed reactor, the circulating fluidized bed reactor having a bed, whereinthe bed is operated in an alternating manner, switching between twosteps: reforming and regeneration; providing a mixture of a fluidizablesolid and a fluidizable nickel-containing reforming catalyst; operatingthe fluidized bed reactor during the reforming step at about 865 to 870°C. and during the regeneration step at about 865 to 900° C., the systempressure at about 50 to 100 psig, and allowing the mixture offluidizable solid and the fluidizable nickel-containing catalyst tocontact a mixture of the hydrocarbon feedstock and the steam feedstockin the reforming step for a period of time such that the product of theweight hourly space velocity (WHSV) and the time online equals from0.001 to 10, preferably 0.01 to 1.64 and more preferably 0.01 to 0.25;operating the fluidized bed reactor during the regeneration step atabout 900° C., the system pressure at about 50 to 100 psig, and allowingthe mixture of fluidizable solid and the fluidizable nickel-containingcatalyst to contact a fuel feedstock and the air feedstock to removecoke and sulfur from the mixture of fluidizable solid and thefluidizable nickel-containing catalyst; converting the nickel-containingcatalyst to the nickel-oxide form during the regeneration step;generating a synthesis gas product stream with at least 25 volume %hydrogen and at most 1.0 volume % nitrogen; operating the circulatingfluidized bed reactor with essentially no supplemental oxygen for thereforming step, other than the oxygen in the form of nickel-oxide fromthe regeneration step and oxygen contained in the steam feedstock and inthe heavy oil feedstock; operating the reforming bed with an S/C ratioat least 1.0, wherein, the nickel-containing reforming catalyst has anickel content of from 10-20 weight percent, a magnesium aluminatesupport, a particle size from 63 to 225 um, and; producing hydrogen as aproduct of the reforming bed.

Another embodiment of the invention is a fluidized bed hydrocarbon steamreforming process using a regenerable catalyst to produce hydrogen, theprocess comprising: providing a hydrocarbon feedstock that has an APIgravity between −11 and +54; providing a steam feedstock; providing afuel feedstock; providing an air feedstock; providing a circulatingfluidized bed reactor, the circulating fluidized bed reactor having abed, wherein the bed is operated in an alternating manner, switchingbetween two steps: a reforming step and a regeneration step; providing afluidizable mixture, the fluidizable mixture comprising a fluidizablesolid and a fluidizable nickel-containing reforming catalyst; operatingthe fluidized bed reactor during the reforming step at about 865 to 900°C. and at about 50 to 100 psig, and during the regeneration step atabout 900° C. and at about 50 to 100 psig, and allowing the fluidizablemixture to contact the hydrocarbon feedstock and the steam feedstock inthe reforming step for a time such that the product of the weight hourlyspace velocity (WHSV) of the hydrocarbon feedstock and the time onlineequals from 0.001 to 10; operating the fluidized bed reactor during theregeneration step at about 900° C., at a pressure of about 50 to 100psig, and allowing the fluidizable mixture to contact the fuel feedstockand the air feedstock to remove coke and sulfur from the fluidizablemixture; converting the fluidizable nickel-containing reforming catalystto a nickel-oxide form during the regeneration step; generating asynthesis gas product stream with at least 60 volume % hydrogen on a dryweight basis and at most 1.0 volume % nitrogen on a dry weight basis;operating the circulating fluidized bed reactor with essentially nosupplemental oxygen for the reforming step, other than the oxygen in aform of nickel-oxide from the regeneration step and oxygen contained inthe steam feedstock and in the hydrocarbon feedstock; and, operating thereforming step with a steam-to-carbon ratio at least 1.0, wherein, thefluidizable nickel-containing reforming catalyst has a nickel content offrom 10-20 weight percent, a magnesium aluminate support, a particlesize from 63 to 225 um. Optionally, the process the reforming step isoperated under conditions such that the product of the weight hourlyspace velocity (WHSV) of the hydrocarbon feedstock and the time onlineequals from 0.01 to 1.64, and more preferably the reforming step isoperated under conditions such that the product of the weight hourlyspace velocity (WHSV) of the hydrocarbon feedstock and the time onlineequals from 0.01 to 0.25.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1. Circulating fluidized bed HyRes process.

FIG. 2. Gas chromatogram of ATB.

FIG. 3. Gas chromatogram of “medium” vacuum residuum.

FIG. 4. Gas chromatogram of “heavy” vacuum residuum.

FIG. 5. XRD of an example of a nickel-containing reforming catalyst.

FIG. 6. Schematic of HyRes process as part of a steam reforming plant.

FIG. 7. Some of the reactions taking place in the HyRes process (notincluding water gas shift).

FIG. 8. Historical natural gas prices from 2000 to 2012.

FIG. 9. P&ID for experimental test apparatus used in the examples.

FIG. 10. Single cycle of ATB reforming with S/C=3 using 25 wt % Nicatalyst/75 wt % α Al₂O₃ at 50 psig and 865° C.

FIG. 11. Gas composition for steam reforming ATB at 865° C., 50 psig,S/C=5, 75 wt % Ni catalyst/25 wt % α Al₂O₃.

FIG. 12. Gas composition when steam reforming “medium” VTB at 865° C.,50 psig, S/C=5, 75 wt % Ni catalyst/25 wt % α Al₂O₃.

FIG. 13. Gas composition when steam reforming “heavy” VTB at 865° C., 50psig, S/C=5, 75 wt % Ni catalyst/25 wt % α Al₂O₃.

FIG. 14. Comparison of GC for ATB and the two VTB samples.

FIG. 15. Gas composition when steam reforming DilBit at 865° C., 50psig, S/C=5, 75 wt % Ni catalyst/25 wt % α Al₂O₃.

FIG. 16. Gas composition when steam reforming pyrolysis oil at 865° C.,50 psig, S/C=1, 75 wt % Ni catalyst/25 wt % α Al₂O₃.

FIG. 17. Gas composition when steam reforming Norpar 12 at 865° C., 50psig, S/C=1.76, 75 wt % Ni catalyst/25 wt % α Al₂O₃.

FIG. 18. Details of the heavy oil injector.

FIG. 19. External view of the reactor used in the examples.

FIG. 20. Details of the experimental incoloy 880H fluidized bed reactor.

FIG. 21. Overall process diagram for using the HyRes process to generatehydrogen from biomass fast pyrolysis oil.

FIG. 22. HyRes processing biomass fast pyrolysis oil with a steam tocarbon ratio of 2.

FIG. 23. HyRes processing biomass fast pyrolysis oil with a steam tocarbon ratio of 3.

FIG. 24. HyRes processing biomass fast pyrolysis oil with a steam tocarbon ratio of 5.

FIG. 25. Renewable hydrogen from HyRes combined with distributed biomassfast pyrolysis oil plants, centralized oil collection and transport tothe HyRes plant.

FIG. 26. Hydrogen production from JP-8 using HyRes.

DETAILED DESCRIPTION OF THE INVENTION

The summary of the invention above and in the Detailed Description ofthe Invention, and the claims below, and in the accompanying drawings,reference is made to particular features of the invention. It is to beunderstood that the disclosure of the invention in this specificationincludes all possible combinations of such particular features. Forexample, where a particular feature is disclosed in the context of aparticular aspect or embodiment of the invention, or a particular claim,that feature can also be used, to the extent possible, in combinationwith and/or in the context of other particular aspects and embodimentsof the invention, and in the invention generally.

The term “comprises” and grammatical equivalents thereof are used hereinto mean that other components, ingredients, steps, etc. are optionallypresent. For example, and article “comprising” (or “which comprises”)component A, B, and C can consist of (i.e. contain only) components A,B, and C, or can contain not only components A, B, and C but also one ormore other components.

The term “at least” followed by a number is used herein to denote thestart of a range beginning with that number (which may be a range havingan upper limit or no upper limit, depending on the variable beingdefined). For example, “at least 1” means 1 or more than 1. The term “atmost” followed by a number is used herein to denote the end of a rangeending with that number (which may be a range having 1 or 0 as its lowerlimit, or a range having no lower limit, depending on the variable beingdefined). For example, “at most 4” means 4 or less than 4, and “at most40%” means 40% or less than 40%. When, in this specification, a range isgiven as “(a first number) to (a second number)” or “(a first number)-(asecond number)”, this means a range whose lower limit is the firstnumber and whose upper limit is the second number. For example 25 to 100mm means a range whose lower limit is 25 mm, and whose upper limit is100 mm.

Heavy oil is a hydrocarbon with an American Petroleum Institute (API)gravity between about −11 and 20 which encompasses oil (tar) sandbitumen, vacuum residuum, atmospheric residuum and heavy gas oil. Heavyhydrocarbons have higher concentrations of high molecular weighthydrocarbons, have more aromatic hydrocarbon character, and typicallyhave higher concentrations of sulfur, metals and other contaminants.

The API gravity is related to the specific gravity of the material byAPI=141.5/(sp gr 60/60° F.)−131.5, where (sp gr 60/60° F.) refers to thedensity of the material at 60° F. divided by the density water at 60° F.In general, the lower the value of the API gravity, the heavier thepetroleum fraction or crude oil (ASTM D1298-99 “Standard Test Method forDensity, Relative Density (Specific Gravity), or API Gravity of CrudePetroleum and Liquid Petroleum Products by Hydrometer Method.”)

Bitumen is a heavy hydrocarbon with an API gravity between about −11 and17, generally derived from oil (tar) sand deposits but can also refer toany feedstock that is composed primarily of hydrocarbons that have APIgravities between about −11 and 17.

Naphtha refers to that fraction of crude petroleum from atmosphericpressure distillation that boils between 55° F. and 300° F. and isdivided into light naphtha (b.p.=55-175° F., ° API ˜80), medium naphtha(b.p.=175-300° F., ° API ˜55) and heavy naphtha (b.p.=300-400° F., ° API˜47).

Kerosine (sometimes spelled Kerosene) refers to the atmosphericdistillate cut that boils between 400-500° F. (° API ˜40).

Atmospheric gas oil refers to an atmospheric distillate fraction thatboils between 500 and 650° F. (° API ˜34).

Atmospheric tower bottoms (ATB, a.k.a. atmospheric residuum or longresiduum) is all of the material with b.p.>650° F. (° API ˜20). It iscommonly sent to a vacuum distillation unit or in some refineries, to aresiduum fluid catalytic cracking (RFCC) unit.

Light vacuum gas oil (LVGO) is the fraction from vacuum distillationthat has b.p.=650-850° F. (° API ˜27); heavy vacuum gas oil (HVGO) hasb.p.=850-1050° F. and ° API ˜20.

Vacuum tower bottoms (VTB, a.k.a. vacuum residuum) is the material thatboils above 1050° F. that has a gravity of ° API ˜10. It is typicallyused in the production of asphalt or petroleum coke. It should be notedthat all boiling points listed above 650° F. (all of the vacuumfractions) are equivalent atmospheric boiling points calculated fromdata obtained at reduced pressures because these materials willdecompose before boiling at atmospheric pressure.

Fluidizable solid is a solid material in a powder form, having aparticle size suitable for fluidizing, and also being substantiallyinert and physically hard or otherwise having resistance to attrition.In addition, the fluidizable solid is preferably stable at hightemperatures (the operating temperatures of the process), having a highmelting point and being non-volatile under the operating conditions.Exemplary fluidizable solid materials include alpha alumina, and spinel.

Fluidizable mixture is a combination of two or more fluidizable solids.For example, a mixture of fluidizable alpha alumina and fluidizablenickel-containing reforming catalyst.

Weight Hourly Space Velocity (WHSV) is the weight of feed flowing perunit weight of the catalyst per hour. In the present invention, when thesolid catalyst is used with a solid diluent, the total mass of themixture of the solid catalyst and solid diluent are to be used as themass of the catalyst to calculate WHSV.

The invention relates to a process useful for producing hydrogen from aheavy oil feedstock. The process converts heavy oil (atmospheric towerbottoms, vacuum tower bottoms, residuum, pyrolysis oil, and similarfeedstocks) to a hydrogen-rich syngas using a mixture of a nickelcatalyst and a solid, wherein non-limiting examples include alumina orspinel. The feedstocks include the heavy oil, steam, air and optionallyan additional fuel feedstock, such as petroleum coke (petcoke), toprovide additional heat for the catalyst regeneration reaction. Acirculating fluidized bed process has a reforming bed and a regenerationbed operably connected to each other with conduits for transporting thesolids between each bed in a looping fashion. The steam and heavy oilare fed to the reforming bed where fluidized nickel catalyst and aluminaare contacted with the feedstock producing a hydrogen-rich product gas.The solids circulate (fluidize) in the reforming bed for a period oftime such that the product of the weight hourly space velocity (WHSV)and the time online equals from 0.001 to 10, preferably 0.01 to 1.64 andmore preferably 0.01 to 0.25 at a temperature of about 865 to 870° C.and at a pressure of about 50 to 100 psig, or for a suitable time toprevent irreversible coke and/or sulfur fouling. The solids are moved tothe regeneration bed where air, and optionally additional fuel, areadded to combust the coke and sulfur at about 865 to 900° C. andoptionally up to about 1000° C. This step removes the coke and sulfurfrom the catalyst.

An unexpected embodiment of the invention is how the process toleratesthe sulfur present in a heavy oil feedstock. Sulfur in the feedstockreacts with the nickel in the catalyst to form nickel sulfides, whichare then burned off during regeneration over numerous repeated cycles.By maintaining the correct rate of catalyst circulation between thereformer and the regenerator, the amount of sulfur (and carbon) thatdeposits on the catalyst during the reforming step can be kept lowenough that the catalyst can surprisingly be regenerated with nopermanent loss of activity. When sulfur and carbon are burned off in theregenerator, the nickel metal is converted into nickel oxide (NiO),which is catalytically inactive for hydrocarbon steam reforming.However, when the catalyst (now as NiO/MgAl₂O₄) is exposed tohydrocarbons, the NiO is reduced back to catalytically active Ni metaland hydrocarbon steam reforming resumes.

A reason for the low cost of the HyRes process is that it has theadvantages of oxygen gasification without requiring an oxygen plant(which at an industrial scale would most likely be a cryogenic plant).Because no air is introduced into the gasifier, no nitrogen is added tothe syngas, which improves the efficiency of H₂ recovery.

The feedstock can be a hydrocarbon stream in the refinery, preferablylow value materials such as residuum, catalytic cracker slurry oil, ATBand vacuum gas oil (VGO). Another optional feedstock for HyRes is oilsand bitumen. The hydrogen produced by HyRes may further be used forupgrading bitumen to synthetic crude oil. Another optional feedstock is“dilbit,” which is raw bitumen mixed with 30% condensate (to make thebitumen fluid).

An embodiment of the invention is that the heat capacity of the solids(catalyst and solid diluent) can supply the heat of steam reforming inthe fluidized bed reactor.

Advantages and embodiments of the invention include: (1) A wide varietyof heavy (and light) hydrocarbon feedstocks can be used for syngasgeneration; (2) Syngas is produced at moderate temperatures (˜850 to900° C.) and pressures (ca. 40 to 100 psig) so expensive refractorylined pressure vessels are not required for low pressure operation; (3)Coke and sulfur deposited on the catalyst are burned off in aregenerator using air generating SO₂ (which is may optionally bescrubbed out after cooling the hot flue gas) and CO₂; (4) no nitrogen isintroduced into the syngas (as in an air blown gasifier); (5) no oxygenplant is needed as in a O₂ blown gasifier or autothermal reformer (ATR);(6) syngas may be shifted upstream of the PSA unit using a sour shiftcatalyst, which improves the energy efficiency of the process; (7) fluegas from the regenerator may be used to raise steam, which improvesprocess efficiency; (8) high purity H₂ can be produced from commerciallyavailable PSA systems; (9) the PSA off gas can be burned as fuel gas forincreased overall energy efficiency; (10) hot gas exiting theregenerator can be used to generate steam; (11) the catalyst cantolerate heavy oil components (e.g. high MW aromatics) without foulingbecause of intermittent regeneration in air; (12) short reforming timesminimizes sulfur and carbon accumulation so that they can be burned offin the regenerator before reaching damaging; (13) Capital costs forcirculating fluidized beds are considerately lower than those associatedwith a conventional coal/coke gasifier or conventional steam methanereformer; and (14) catalyst can be removed continuously (orsemi-continuously), to prevent excessive buildup of Ni and V. It isunderstood that some build-up of nickel is not detrimental, as thecatalyst is based on nickel.

The nickel catalyst is a magnesium aluminate that contains about 10 to20 weight percent nickel. The particle size is between 63 and 225 um. Inone example, the alumina has a particle size of about 60 to 90 um and isessentially comprised of alpha-alumina. The nickel catalyst and aluminaare used as a mixture of between about 25 to 75 weight percent nickelcatalyst.

The reforming bed is operated at about 865-870° C., 50-100 psig and anaverage catalyst contact time of a period of time such that the productof the weight hourly space velocity (WHSV) and the time online equalsfrom 0.001 to 10, preferably 0.01 to 1.64 and more preferably 0.01 to0.25. Non-limiting examples of the fuel feedstock are heavy oil, petcokeor mixtures thereof.

Regeneration is operated at about 865-1000° C., about 50 to 100 psig,and with an average catalyst contact time of about 40 to 60 minutes.

The nickel catalyst changes from Ni to NiO and back to Ni in theprocess. The regeneration bed converts it to NiO and when it reaches thereforming bed the hydrocarbons reduce it back to catalytically activeNi.

The syngas produced by the reforming bed contains at least 25 volume °A), preferably at least 60 volume ° A) hydrogen or a H₂ to CO mole ratioof 4 to 7. No air is introduced into the reforming bed, which allows theprocess to produce a high-purity syngas product that contains little tono nitrogen, for example less than 1.0 volume nitrogen.

Steam to carbon ratios are set from 1 to 13.6, or at least 3 and morepreferably at least 5. It is desirable to use the lowest steam to carbonratio that prevents coke buildup.

The heavy oil feedstock is typically a low-value, hard to process heavycomponent from crude oil refining. Other heavy oil can be produced bythe pyrolysis of biomass. Non-limiting examples of heavy oil feedstocksinclude atmospheric tower bottoms, vacuum tower bottoms, oil sandsbitumen, biomass pyrolysis oil, solid municipal waste pyrolysis oil, andresiduum. The ATB and VTB samples used in the examples below wereobtained from U.S. refineries, the bitumen was obtained from a Canadianoil sands producer, biomass pyrolysis oil was obtained from the NationalRenewable Energy Laboratory, and the NorPar 12 was purchased fromExxonMobil.

In the accompanying examples, the use of various feedstocks was reducedto practice in the HyRes process: These non-limiting examples offeedstocks include: (1) atmospheric tower bottoms (atmospheric residuum)from the Valero Krotz Springs refinery; (2) a medium heavy vacuum towerbottoms (vacuum residuum) from Valero's Corpus Christi refinery; (3) avery heavy vacuum tower residuum from an ExxonMobil Louisiana refinery;(4) diluted tar sand bitumen from Canada; (5) Norpar 12, an ExxonMobilsolvent product; and (6) biomass fast pyrolysis oil from the NationalRenewable Energy Laboratory (NREL).

Valero's Krotz Springs refinery is a topping refinery as there is novacuum unit. Atmospheric tower bottoms (ATB) is sent to the fluidcatalytic cracker (FCC) to make a low octane FCC gasoline. Naphtha fromthe crude unit is reformed and mixed with polymerized FCC naphtha andisomerate to make gasoline. ATB is the stream from atmosphericdistillation of crude oil that boils at >650° F. that is normally sentto vacuum distillation. The ATB has an elemental composition of 86.64 wt% carbon, 12.15 wt % hydrogen, 0.12 wt % nitrogen, 0.55 wt % oxygen and0.81 wt % sulfur (and an H to C ratio of 1.68 on a mole basis). The ATBwas pourable at room temperature. Sulfur reacts with the nickel intypical steam reforming catalysts. However, in the HyRes process,surface sulfur is burned off during regeneration (forming NiO and SOx)before bulk nickel sulfides can form that would irreversibly damage thecatalyst.

Vacuum Tower Bottoms were received from the Valero Corpus Christi Plant.Normally vacuum tower bottoms (residuum) has the consistency of tar(solid at room temperature); however, the VTB from the Corpus Christiplant is far less viscous. Therefore we refer to the Corpus Christi VTBas “medium” VTB. The elemental analysis from the Corpus Christi mediumVTB is 87.09 wt % carbon, 12.42 wt % hydrogen, 0.21 wt % nitrogen, 0.28wt % oxygen and 0.27 wt % sulfur. The hydrogen to carbon (H/C) ratio isabout the same as that of the Krotz Springs ATB; however, the CorpusChristi VTB is lower in sulfur.

Heavy VTB was received from ExxonMobil. The heavy VTB was a solid atroom temperature and had an elemental composition of 86.09 wt % carbon,10.98 wt % hydrogen, 0.43 wt % nitrogen, 0.52 wt % oxygen and 2.02 wt %sulfur. The H/C ratio was 1.53.

ExxonMobil Norpar 12 was used as a kerosine simulant. Norpar 12 (normalparaffin) is a ˜50:50 mixture of C₁₁ (b.p.=379° F.) & C₁₂ (b.p.=417° F.)n-paraffins.

Biomass Fast Pyrolysis Oil was received from NREL (National RenewableEnergy Lab, Golden Colo.). In pyrolysis, biomass is heated in theabsence of air to generate a bio-oil that contains water, water solubleorganics, and a water insoluble phase (primarily phenolic compoundsproduced from the lignin). The other products are char and gas, andthese can be minimized by increasing the rate of pyrolysis, to maximizethe bio-oil yield. There are several problems with converting bio-oilinto chemicals and fuels. First, raw bio-oil is unstable and will slowlypolymerize if left to stand unless stabilized (it contains a lot ofreactive species such as aldehydes). Second, it is a very complexmixture of compounds. These properties make direct conversion ofpyrolysis oil to fuels and chemicals difficult.

An as-received sample (brown liquid) was characterized prior to use. Thedensity was 1.127 g/cc and the pH was 3. It was preferentially solublein water but not hexanes consistent with containing not only water butalso polar organic compounds. The elemental composition was 27.36 wt %carbon, 8.81 wt % hydrogen, 62.85 wt % oxygen and it had an H/C ratio of3.86 on a mole basis)

In a preferred embodiment the catalyst is a commercial steam methanereforming catalyst (a non-limiting example is the commercial productTopsøe R-67-7H). This catalyst is mixed with low surface area α-Al₂O₃where both solids have been screened to have particle sizes near 100 um.R-67-7H, which is manufactured by Haldor Topsøe, contains about 12 wt %Ni supported on a MgAl₂O₄ carrier. Both the R-67-7H and the α-Al₂O₃ arevery hard, attrition resistant materials (necessary for durability in afluidized bed reactor). Topsøe R-67-7H is a reforming catalyst with >12wt % nickel, SiO₂ wt %<0.2 wt %, and a nickel surface area of 3.5-5m2/g.

The base material of the R-67-7H carrier is magnesium aluminate, aceramic inert oxide of the spinel family known for excellent stabilityat the entire range of temperatures. Furthermore, the catalyst does notsuffer any degradation, either by exposure to condensing steam duringstart-up or by high temperature steaming, and in the case of HyRes isnot damaged by repeated cycles of steam reforming and regeneration, norby controlled exposure to coke and sulfur. Other suitable reformingcatalysts with these properties may be substituted for R-67-7H.

Atmospheric tower bottoms (ATB) are produced in refineries. As anexample, a capillary column gas chromatogram of a sample of ATBdissolved at a concentration of 10 mg/mL in dichloromethane is shown inFIG. 2. The data shown in FIG. 2 were obtained using a computercontrolled Varian CP 3600 gas chromatograph equipped with a ASTM D2887simulated distillation capillary column and a flame ionization detector(FID). The baseline increases due to column bleed at high temperatures(the temperature at the highest point in FIG. 2 occurs at T=340° C.(644° F.). Even though the ATB stream is typically 650+° F. material,small amounts of volatile hydrocarbons are still present that elute fromthe GC column between 30 and 60 min, which corresponds to about 250-600°F.

An even heavier oil than ATB is medium vacuum tower bottoms. An exampleof a medium VTB sample from a refinery was analyzed in a gaschromatograph and the result is shown in FIG. 3. The data shown in FIG.3 were obtained using a computer controlled Varian CP 3600 gaschromatograph equipped with a ASTM D2887 simulated distillationcapillary column and a flame ionization detector (FID). While thismaterial was a solid at room temperature (the ATB was a viscous liquidat room temp), its GC analysis was similar to the ATB in that kerosinethrough gas oil hydrocarbons were present (to about the same extent).Some heavier components appear as well. The main reason that the heaviercomponent peaks are not larger is that this medium VTB is less solublein dichloromethane (CH₂Cl₂) than ATB.

The heavy VTB is only slightly soluble in dichloromethane (CH₂Cl₂) sothe peaks in the raw GC data are quite small (FIG. 4). Nevertheless, thequalitative comparison shows that this VTB is considerably heavier thanthe medium VTB and therefore contains greater amounts of high molecularweight hydrocarbons.

Because VTB is contains the highest boiling fractions of the originalcrude, all of the metals and much of the sulfur is concentrated in thismaterial. Typical contaminant concentrations in vacuum residuum are:sulfur 2-7 wt %, nitrogen 0.2-0.7 wt % (mostly as heteroatom aromatics),oxygen ˜1 wt % (phenols etc.), vanadium 100-1000 ppm and Ni 20-200 ppm.

Other examples of heavy oils should be understood by a Person HavingOrdinary Skill in The Art.

The steam feedstock is comprised essentially of water vapor. The steammay be generated by a dedicated steam unit, waste steam from anotherunit operation, or waste heat recovered and used to at least partiallyheat the steam. The steam is injected into the reforming bed of thecirculating fluidized bed reactor at about 865 to 870° C. and about 50to 100 psig.

The fuel feedstock is added to the regeneration bed to promote theremoval of coke and sulfur on the solid catalyst and solid alumina. Thecoke on the solids will act as one source of fuel (in combination withthe added air) to combust the coke and remove the sulfur as sulfurdioxide or other sulfur oxides. There may not be enough coke on thesolids to drive the combustion reaction and to heat the solids to about900° C., so additional fuel feedstock is added. The fuel can beadditional unprocessed heavy oil feedstock, petcoke or other suitablecompounds that are understood by a Person Having Ordinary Skill in TheArt.

The air feedstock is a compressed gas stream. Compress air or a mixtureof oxygen, and nitrogen with other optional gases including carbondioxide, or pure oxygen may be used as the air feedstock. The compressedair feedstock is at a pressure of about 50 to 100 psig and containsenough oxygen or to drive the combustion reaction in the regenerationbed.

The circulating fluidized bed may optionally be a looping reactorcontaining at least a fluidized reforming bed and a fluidizedregeneration bed operably connected to each other by conduits for solidstransport from the top of each bed to the bottom of the other. Anexample of a circulating fluidized bed reactor is shown in FIG. 1. Thefigures and drawings and the description of the figures and drawingsshould be understood by a Person Having Ordinary Skill in The Art asrepresenting a class of reactors systems that can have varyingconfigurations relative to the specific configuration in FIG. 1. Thereforming bed has a heavy oil feedstock 10 and a steam feedstock 20.Heavy oil feedstock 10 is injected into the reforming bed 50 via aninjector 52. Steam is added via a manifold 56. The solid mixture of afluidizable nickel-containing reforming catalyst and a fluidizablealpha-alumina 70 is contained in the reactor and moves between both beds50 and 60 via transporting conduits 54 and 64. A screen 57 supports thesolids at the lower end of the reactor 50. The product gasses leave thereforming bed through exit 58. Solids are prevented from leaving byusing an enlarged diameter disengaging zone 59 and a filter 53. Theproduct gas stream 80 comprises a high-concentration hydrogen syngas,preferably where at least 25 vol % is hydrogen, and more preferably atleast 60 vol % is hydrogen. Additional make-up solid catalyst and solidalumina 71 may be added to the transport conduit 54 via inlet valve 72.The regeneration bed 60 also contains a degassing zone 69 and an inlet66 and an injector 62. In this bed the fuel feedstock 30 and airfeedstock 40 are added to the regeneration bed. If the fuel is a solid,such as petcoke, and can be added with the solid make-up catalyst 71 viavalve 72 or can be entrained as small particles in the air feedstock 40.The solid mixture 70 also fluidizes in the regeneration bed 60 andreturns to the reforming bed 50 via conduit 64. The regeneration bed 60contains an exit port and valve 74 where spent catalyst and solidalumina 73 can be removed. The product gas stream of the regenerator 90exits via the exit port 68. A filter 63 and enlarged top section of thereactor 69 prevent solids from exiting with the gas stream.

The fluidized bed comprises a mixture of a fluidizable solid, preferablyalpha-alumina and a fluidizable nickel-containing reforming catalyst.The alpha-alumina may have a particle size range from 60 to 225 um, orpreferably from 60 to 90 um. The alpha-alumina may be produced in aspray drying process with a surface area of from 0.1 to 10 m²/gram.Preferably the surface area may be from 0.25 to 8 m²/gram, or about 0.25or about 8 m²/gram. The amount of silica contained in the alpha-aluminacan be less than 3%, preferably less than 1%.

The nickel-containing reforming catalyst comprises a magnesium-aluminatesupport with nickel at a loading amount of 10 to 20 weight %, preferably12 to 15 weight %. The particle size may be about 60 to 225 um,preferably about 106 to 225 um. The nickel-containing catalyst can becycled from the Ni to the NiO form, reversibly.

In a preferred embodiment the nickel-containing catalyst may have a BETMultipoint Surface Area of about 1.47 m²/g prior to using in thecirculating fluidized bed and the catalyst can undergo physical changesin the circulating fluidized bed that increase the surface area to about12.80 m²/g. The nickel-containing catalyst used in examples 3, 4 and 5had a surface area before and after use of about these values.

The nickel-containing catalyst may be analyzed using an X-raydiffractometer (XRD) to establish the presence of themagnesium-aluminate support and the deposited nickel in the oxide form.FIG. 5 shows an example of an XRD scan of a suitable example of thecatalyst.

A feature of the alumina (or other solid) and catalyst is the particlesize. The particles must be about 60 um up to about 225 um. Anotherfeature is the nickel loading level, which may be about 10 to 20 weight%. These features combined with operating conditions discussed in thefollowing sections (specifically, the residence time such that theproduct of the weight hourly space velocity (WHSV) and the time onlineequals from 0.001 to 10, preferably 0.01 to 1.64 and more preferably0.01 to 0.25 in the reforming bed) form a set of elements of thisinvention that provide for a process that can generate hydrogen fromheavy oil using a circulating fluidized bed reactor that can operatecontinuously for a period of time without suffering from coke, sulfur orother material build-up or catalyst deactivation. In addition thecombination of these features allow for a heavy oil reforming processthat does not require adding air or oxygen to the reforming bed, thus aproduct gas with a high level of hydrogen product is produced (at least25 vol %, more preferably at least 60 vol %).

An embodiment of the invention is the resistance of the catalyst toattrition in both the reforming and regeneration beds due to particlescolliding and abrading against each other when fluidized.

In an embodiment, heavy oil and steam are fed into a fluidized bedreactor containing a nickel steam reforming catalyst at 870° C. togenerate syngas (CO+H₂). Because the process uses contact times suchthat the product of the weight hourly space velocity (WHSV) and the timeonline equals from 0.001 to 10, preferably 0.01 to 1.64 and morepreferably 0.01 to 0.25, not enough carbon or sulfur build up on thecatalyst to cause irreversible deactivation. The catalyst is thenregenerated by burning the coke and sulfur off with air. In thelaboratory, this may be done using a single reactor with a nitrogenpurge between reforming and regeneration steps; however, in anindustrial setting, a circulating fluidized bed system would be used.Burning off the coke and sulfur in the regenerator reheats the catalystto about 900° C. for the next reforming step (a small amount ofresiduum, heavy oil or other fuel can be added to the regenerator toincrease the temperature if there is not enough coke on the catalyst).The hot nickel catalyst returning to the reforming reactor is present asNiO but is quickly reduced to catalytically active nickel metal by thehydrocarbons in the feed.

The solid diluent, an example of which is alpha-alumina, provides addedthermal capacity because of its mass and heat capacity and helps preventirreversible coke buildup on the active nickel-containing catalystsurface by physically diluting it from about 25 to 75 weight percent.The thermal mass of alumina improves heat transfer. In an embodiment thenickel-containing catalyst makes up about 50 to 75 weight percent of themixture and in a preferred embodiment the nickel-containing catalystmakes up about 75 weight percent of the mixture.

Petcoke (petroleum coke) can be used as the fuel feedstock.Conveniently, petcoke is a low-value material typically available inrefineries. Solid fuel feedstocks such as petcoke may be added to theprocess with the make-up catalyst.

From the reforming reactor, the catalyst is sent to a regeneration bed,where coke and sulfur are burned off with air and the catalyst isreheated to about 900° C. (a small amount of fuel, such as heavy oilfeed or petcoke is added as additional fuel). The catalyst returns tothe reactor as inactive nickel oxide, but it is quickly reduced back tocatalytically active Ni metal by the hydrocarbons in the feed.

Because the catalyst can reversibly shuttle between the reduced Ni stateand the oxidized NiO state the physical passing of the solid mixturefrom the regeneration bed to the reforming bed and back has the effectof transporting oxygen from the regeneration bed (on the solid) to thereforming bed. This is important because air can be used for catalystregeneration (instead of O₂ which requires an air separation plant)while keeping the syngas produced by the reformer from being dilutedwith nitrogen.

Examples 3-5 provide operating conditions that use a heavy oil feedstockand generate a syngas product with at least 60 volume present hydrogenon a dry gas basis, or after excess water has been condensed. In anotherembodiment the syngas product has a hydrogen to CO mole ratio of from 4to 6. Example 7 provides operating conditions that use pyrolysis oil andgenerate a syngas product with at least 25 volume % hydrogen on a drygas basis, or after excess water has been condensed. The hydrogencontent is lower due to the presence of water in the pyrolysis oil feed.

In one embodiment the steam to carbon molar ratio for the feedstocks inthe reforming bed is from 1.75 to 5. In another embodiment it is from 3to 5. The process can use heavy oil feedstocks including, but notlimited to, atmospheric tower bottoms (ATB) and vacuum tower bottoms(VTB) as feedstocks,

The process can steam reform heavy hydrocarbon fractions such asatmospheric and vacuum residuum (also called atmospheric tower bottoms,ATB and vacuum tower bottoms, VTB) over nickel based catalysts withoutcatalyst deactivation (FIG. 6). The catalyst is not deactivated in theprocess because it is regenerated in air at regular intervals. In acirculating fluidized bed system, the catalyst is continuouslyregenerated. The catalyst is regenerated after about a period of timesuch that the product of the weight hourly space velocity (WHSV) and thetime online equals from 0.001 to 10, preferably 0.01 to 1.64 and morepreferably 0.01 to 0.25, for the reforming reaction.

Heavy oil and steam are fed into a fluidized bed reactor containing a Nisteam reforming catalyst at about 865 to 870° C. to generate syngas(CO+H2). Because reforming is carried out for only a period of time suchthat the product of the weight hourly space velocity (WHSV) and the timeonline equals from 0.001 to 10, preferably 0.01 to 1.64 and morepreferably 0.01 to 0.25 before the catalyst is regenerated, the amountof carbon (coke) and sulfur that build up on the catalyst surface arenot sufficient to cause irreversible deactivation. The catalyst is thensent to a regenerator where the coke (and sulfur) are burned off withair. Combustion of coke on the catalyst surface (C+O₂→CO₂, ΔH=−94kcal/mole) and the oxidation of nickel on the catalyst to nickel oxide(Ni+½O₂ NiO, ΔH=−56 kcal/mole) supply most of the heat required toincrease the catalyst temperature back up to ˜900° C. in theregenerator; however, additional heavy hydrocarbon feed (or petcoke) canbe burned in the regenerator if needed to increase the catalysttemperature. The hot catalyst returning to the reforming reactor is nowin the form of nickel oxide, which is catalytically inactive for steamreforming; however, in the process, the hydrocarbons in the feed quicklyreduce the NiO back to catalytically active Ni for the next reformingcycle (xNiO+C_(x)H_(y) xCO+y/2H₂+xNi). In an industrial sized unit(where heat losses are lower compared to the laboratory scale), thesensible heat in the catalyst and inert solids added will provide mostof the endothermic heat required by the steam-hydrocarbon reformingreactions. The catalyst flow, feed, steam and regenerator fuel rates areadjusted to maintain the proper heat balance in the process. FIGS. 6 and7 show examples of the heavy oil steam reforming process.

The process has advantages described in the BACKGROUND section. Thereare additional advantages related to the process economics. Theeconomics of hydrogen generation in refineries strongly depends onfeedstock cost. The price of natural gas for industrial consumers iscurrently low (FIG. 8) making steam methane reforming (SMR) economicallyattractive for generating hydrogen. The selling price of “bottom of thebarrel” products depends on the price of petcoke (steel making demandsin China have recently pushed up petcoke prices), whether there is amarket for heavy fuel oil made by cutting residuum with a lighterdistillate fraction, and asphalt prices. Nevertheless, increasing gasprices or lack of steam methane reforming infrastructure (e.g. smallerrefineries), make a hydrogen from heavy oil process more economicallyattractive.

Another area where a heavy oil reforming process is useful is forgenerating hydrogen for upgrading bitumen during syncrude production.Currently, one of the most common methods for syncrude production is toprocess raw oil sand bitumen in a coking unit, which converts about40-50 weight percent of the carbon in the bitumen into coke. Theremaining liquid syncrude is then piped to refineries. Because cokingthe bitumen removes what would otherwise be the bottoms fraction of thecrude, the syncrude must be eventually blended with conventionalpetroleum so that it can be processed in existing refineries. By usingbitumen to produce hydrogen it is possible to either reduce the amountof coking needed to produce syncrude by hydrotreating the bitumendirectly, or upgrade syncrude produced by conventional methods before itenters the pipeline.

The heavy oil reforming process is less expensive than partial oxidation(PDX) or heavy oil gasification because it has the advantages of oxygengasification without the need for an expensive oxygen plant, and theprocess temperature is much lower than those required by gasification(the heavy oil reforming process operates at about 865 to 900° C.,whereas gasification operates at or greater than 1100° C.). Because theprocess uses a separate vessel for catalyst regeneration, no nitrogen isintroduced into the syngas, which improves the efficiency of downstreamwater gas shift and hydrogen separation operations. Economic analysisindicates that the process can produce hydrogen for approximately $4-5per 1000 SCF compared with about $5-9 per 1000 SCF from a small (0.5-10MMSCFD) steam methane reforming plant, or purchasing delivered liquidhydrogen for about $9-28 per 1000 SCF.

As refineries process increasingly heavy, sour crudes (as well as theincreased use of oil sand bitumen) more hydrogen will be required toremove metals, sulfur and nitrogen, and to upgrade highly aromaticfeedstocks into distillate fuels. Most large refineries have delayedcokers that are used to convert bottom of the barrel streams intopetroleum coke, naphtha and gas oils. Very few have petroleum cokegasifiers for generating hydrogen due to their extremely high cost. Whenthe market for petcoke is good, coking can be economically attractive.In poor markets, petcoke may sell for less than a barrel of crude (on acarbon basis) and in that case coking is mostly a way to get rid ofbottom of the barrel hydrocarbons (obviously, this is offset somewhat bythe value of the naphtha and gas oils produced by the coker). Somerefineries have steam methane reformers onsite, and some purchase H₂from a vendor (e.g. Air Products, Praxair, et al.). Both large and smallrefineries can benefit from the present HyRes process, especially as analternative to coking. For large refiners, HyRes is a way to increase H₂capacity without installing additional steam methane reforming (SMR) orpartial oxidation (PDX) capacity. For small refineries, (˜50,000 bbl/dayand smaller), the installation of SMR (let alone a heavy oil or petcokegasifier) is economically unattractive. The HyRes process isparticularly well suited for use in these smaller refineries. Theestimated H₂ production costs for a 19 MMSCFD hydrogen plant based onHyRes is $11.40 per MMBtu (or $0.696 per LB), with a total plant capitalcost of approximately $5 million. This is lower than the cost of a steammethane reformer plant of similar size, which is about $14/MMBtu,assuming natural gas at a cost of $5 per MCF.

In the above cost analysis of the HyRes process, all of the flows werebalanced with heat losses in every component when the H₂ yield and fuelrequirements were calculated. Using a cost of VTB in 2007 of $7/MMBTU,and including credits for power produced and CH₄ in the syngas. The costof generating H₂ from natural gas is approximately $/MSCF ofH₂=0.45*NG+1.02. Using this formula and natural gas at a cost of$5.50/MCF gives a H₂ production cost of $3.50/MSCF of H₂, or$10.75/MMBTU (in 2014$). H₂ from HYRES costs ˜$11/MMBTU; thus, HyRes iseconomically competitive with natural gas even at low gas prices.

Another area where the HyRes process is useful is for generatinghydrogen for upgrading oil sand bitumen during syncrude production.Currently, syncrude is made by coking raw oil sand bitumen, whichconverts about 40-50 wt % of the carbon in the bitumen into coke (notall of which is utilized). The liquid syncrude is then piped torefineries. Because coking the bitumen removes what would otherwise bethe bottoms fraction of the crude, the syncrude is blended withconventional petroleum so that it can be processed in existingrefineries (that were designed for processing conventional petroleum).The HyRes process is suitable for using dilbit (30% condensate+70% rawoil sand bitumen to produce hydrogen for long operating periods with nocatalyst deactivation. By using bitumen to produce hydrogen, it may bepossible to either reduce the amount of coking needed to producesyncrude by hydrotreating the bitumen directly, or upgrade syncrudeproduced by conventional methods before it enters the pipeline.

Finally, the main reason that our residuum steam reforming process isless expensive than partial oxidation (PDX) or heavy oil gasification isthat the HyRes process has the advantages of oxygen gasification withoutthe need for an expensive oxygen plant, and that the feedstock can beeasily handled and steam reformed at temperatures much lower than thoserequired by gasification (the present process operates at about 1562° F.(850° C.), whereas gasification operates at temperature of 2192-2642° F.(1200-1450° C.) (Rezaiyan and Cheremisinoff 2005). Because HyRes uses aseparate vessel, or optionally the same vessel used in a separateprocess step, for catalyst regeneration, no nitrogen is introduced intothe syngas, which improves the efficiency of downstream water gas shiftand hydrogen separation operations. An economic analysis indicates thatHyRes can produce hydrogen for approximately $4-5/1000 SCF using ourprocess compared with ˜$5-9/1000 SCF from a small (0.5-10 MMSCFD) steammethane reforming plant, or purchasing delivered liquid hydrogen for˜$9-28/1000 SCF.

Other examples of commercial catalysts designed for heavier feedstocksinclude the Haldor Topsøe catalysts such as AR-401, a naphtha pre-steamreforming catalyst containing 35% Ni on MgAl₂O₄, AR-301 (30% Ni onMgAl₂O₄), and RKNGR (25% Ni, 11% Al₂O₃, balance MgO).

Example 1: preparing the nickel-containing catalyst from a commerciallyavailable reforming catalyst. A commercial steam reforming catalyst suchas Haldor Topsøe R-67-7H (<12% Ni/MgAl₂O₄ is ground and screened to aparticle size of −250 to +106 mesh. Approximately 375 grams of thiscatalyst is then mixed with 125 grams of alpha-alumina (Saint GobainNorPro SA5397) that was ground and screened to the same particle size.The densities of the Ni catalyst and alpha alumina are close enough thatthe same particle size can be used in the fluidized bed reactor (i.e.the particles have minimum fluidization velocities that are essentiallyidentical). Other commercial Ni catalysts designed for hydrocarbon steamcan be used with and without promoters. A non-exhaustive list ofexamples of promoters used in commercial Ni steam reforming catalystsinclude MgO, CaO, and lanthanum, cerium and lanthanide group elements.Alkali metals (notably potassium) are sometimes added to improve thecoking resistance of the catalyst.

Example 2: preparing a nickel-containing catalyst. Ni steam reformingcatalysts are typically made using a coprecipitation technique.Impregnation is not commonly used because the resulting catalysts arenot strong enough for use in the tall (ca. 20 m) commercial fixed bedsteam reformer tubes. Other metals such as Pt, Ru and Pd are also activefor steam reforming of hydrocarbons but are cost prohibitive. This isbecause the high operating temperatures used in catalytic hydrocarbonsteam reforming sinter the catalyst so that only 5-10% of the metal inthe catalyst is actually exposed at the surface for catalysis. As aresult, essentially all hydrocarbon steam reforming catalysts usenickel.

Preparation of a Ni catalyst by coprecipitation: Nickel nitrate(Ni(NO₃)₂) sufficient to obtain the desired wt % Ni (10 to 20 wt %) inthe final catalyst is dissolved in distilled water. Aluminum nitrate(Al(NO₃)₃) is then dissolved in the same solution, and if desired,magnesium or calcium nitrates, lanthanide nitrates, etc. can added asmodifiers. Magnesium and calcium are added to form Mg and Ca aluminateswhich are hard, dense spinel phases that greatly increase the mechanicaldurability of the catalyst. Sufficient base (NH₄OH, KOH or NaOH) is thenadded to co-precipitate nickel, aluminum and calcium or magnesium astheir hydroxides. The precipitate is then washed free of ammonium (or Naor K) ions and allowed to age. The gel is then dried at approximately120° C. overnight and then calcined at 500° C. overnight, followed by ahigh temperature calcining (800° C.) for several hours. The catalyst isthen ground and sieved to the appropriate size for use in the fluidizedbed reactors.

Preparation of α Al₂O₃: Alpha alumina is made in a similar fashion;aluminum hydroxide (Al(OH)₃) is precipitated from an aluminum nitratesolution using base followed by washing, drying and calcining. A finalcalcining at approximately 1100° C. is required to ensure that the alphaphase of aluminum oxide if formed. The alpha phase is used because it isthe most stable high temperature phase of alumina, and having aclosest-packed structure of aluminum and oxide ions is dense andmechanically durable.

Examples 3-10 use the following laboratory fluidized bed reactor.Experiments used the apparatus shown in FIG. 9. The apparatus uses asingle fluidized bed, which is cycled between reforming andregeneration. The reactor is briefly purged with nitrogen between stepsto prevent mixing air with heavy oil/syngas. Electronic mass flowcontrollers are used to feed five gas streams to the reactor via ¼″-316stainless steel tubing. Each gas stream can be isolated by pneumaticallyactuated valves. There is also a high pressure liquid pump (ISCOstainless steel “syringe pump”) that is used to feed water to a boiler(a tubing coil in a furnace) where it is vaporized into steam. A secondISCO high pressure liquid pump is used to feed heavy oil to ahot-water-jacketed injector where a nitrogen sweep aids in oil delivery.The oil pump has a heated jacket filled with silicone oil at 70-90° C.that is circulated by a heated oil bath to keep the viscosity of theheavy oil low enough that it can be pumped.

Due to the high steam reforming temperatures used (800-900° C.), thefluidized bed reactor is made from SCH40 Incoloy 800H pipe. A section of4″ pipe is used as a “disengaging zone”, which is welded to a 4″×2″ bellreducer that is attached to a section of 2″ pipe that contains thecatalyst bed. The catalyst bed contains about 500 g of a mixture of Nisteam reforming catalyst and fluidizable α Al₂O₃. Downstream from thereactor, a 10 μm filter collects any catalyst dust that is entrained inthe gas flow, a heat exchanger/condensing coil to remove water, and asodium citrate bubbler/scrubber to prevent H2S (during reforming) andSO₂ (during regeneration) from entering (and possibly damaging) theonline H₂, CO, CO₂, CH₄ gas analyzer (Nova Analytical Systems). There isalso a separate online paramagnetic O₂ analyzer. The system pressure iscontrolled using a computer-controlled, pressure control valve (PCV)made by Badger Meter Co. A PC running OPTO22 software controls the PCVas well as the heating tapes, tube furnace, mass flow controllers andother components of the system, as well as logs the data and monitorsthe system so that in the event of a malfunction, can safely shut downthe apparatus.

The gas flow rates were determined by first measuring the minimumfluidization velocity of the catalyst particles in a cold flow apparatususing air. The minimum fluidization velocity (U_(mf)) is where the bedof particles just begins to bubble when gas is passed through adistributor up through the bed. A convenient way to do this is to plotthe differential pressure drop across the bed of particles versus thesuperficial gas velocity up through the bed. At low flows, the particlesdon't move and the pressure drop is linear (fixed bed behavior).Increasing the gas flow expands the bed until incipient fluidizationstarts at U_(mf). At this point the drag forces of the rising gas on theparticles is just balanced with gravitational forces, so U_(mf) is closeto the terminal velocity of the particles. For quietly bubbling bedoperation, typically 2-5 U_(mf) is chosen as the operating gas velocity.

If the pressure is then decreased, there is a hysteresis in the pressureversus flow plot because the bed had been expanded so the pressure dropis slightly less for a given gas velocity. Above U_(mf) the curve isfairly flat and the bed quietly bubbles until the gas velocity reaches apoint where entrainment of the particles becomes evident. At this point,the gas velocity is greater than the terminal velocity of the particlesand they are ejected from the bed. This generally occurs at around 20 ormore times U_(mf).

Because the particle sizes of crushed solids are typically not uniform,depending on the particle size distribution, obtaining fluidization withthe larger particles, may necessarily put some of the small particles inentrained flow. Thus it is preferable to have a larger section of pipeabove the main reactor section as shown in 1, FIG. 19 and FIG. 20. Inthe apparatus used in Examples 3-10, the main reactor is made from 2inch SCH40 Incoloy 800H pipe that is about 18 inches tall. Welded tothis is a conical adapter (so that catalyst does not hang up whendescending) to which a 4 inch pipe section about 8.5 inches long isattached. Since the cross sectional area of the pipe varies with thesquare of the diameter, the area of the 4 inch section is about 4 timeslarger than that of the 2 inch reactor section so the gas velocity dropsto 25% of its value in the 2 inch reactor section, and this allows anyof the smaller particles to slow down and drop back into the reactor.Extremely fine material that still remains entrained is trapped byfilters. An embodiment of this invention is the use of an attritionresistant catalyst and solid diluent and the screening of the catalystand solid to remove fines at the start of a run, the amount of finesthat must be trapped by the filters is minimized.

The Ergun Equation:

${{\frac{1.75}{\phi_{s}ɛ_{mf}^{3}}\left( \frac{d_{p}U_{mf}\rho_{g}}{\mu_{g}} \right)^{2}} + {\frac{150\left( {1 - ɛ_{mf}} \right)}{\phi_{s}^{2}ɛ_{mf}^{3}}\left( \frac{d_{p}U_{mf}\rho_{g}}{\mu_{g}} \right)}} = \frac{d_{p}^{3}{\rho_{g}\left( {\rho_{s} - \rho_{g}} \right)}g}{\mu_{g}^{2}}$The Ergun Equation can be used to calculate the pressure drop. Thisclassic correlation is quadratic in the particle Reynolds number,N_(Re)=(d_(p)U_(mf)ρ_(g))/μ_(g) and, when solved for N_(Re), the minimumfluidization velocity can be calculated. The implicit assumption forthis equation is that the particle size is uniform. However if theparticle size is known (d_(p)), along with the void fraction at U_(mf)(ε_(mf)), their sphericity (ϕ_(s)), the viscosity and density of the gas(μ_(g) and ρ_(g)), and the density of the particles (ρ_(s)), U_(mf) canbe found. Experimentally, most of these values are usually not knownexactly (especially ϕ_(s) and ε_(mf)) and measuring them is tedious.Also, a perfectly uniform particle size is undesirable and a smallfraction of smaller particles improves fluidization. A preferred way todetermine U_(mf) is cold flow testing with air at room temperature andpressure. Once U_(mf) is known under these conditions, either ϕ_(s) orε_(mf) can be used as adjustable parameters to make the data fit withair, and then these values can be used to calculate U_(mf) with the gasof interest (in our case steam) at 850° C. and 50 psig, as exemplaryconditions selected from the range of conditions described in theexamples of this application.

FIG. 18 shows the details of a heavy oil injector of the presentinvention. The central problem with feeding heavy oil is that it cannotbe vaporized at ambient or higher pressures by heating alone withoutthermal decomposition. As a result, it is injected into the reactor asan aerosol of fine droplets. For the apparatus used in Examples 3-10,penetrating the wall of the reactor just above the fritted disk is a0.5″×0.049″ wall stainless steel tube. Inside of this is an alumina tubethat acts as a thermal insulator for a thin ( 1/16^(th) inch OD) tubeinside it. Heavy oil is injected through this 1/16^(th) inch tube. Thesmall diameter ensures high velocity to minimize the residence time ofthe oil in the tube to prevent coking. The heavy oil is fed to theinjector using an ISCO syringe pump.

The experimental apparatus is a bubbling fluidized bed reactor for thesingle bed tests. The same bed is used for reforming and regeneration inalternating steps. The reactor optionally use a variety of feedstocksincluding heavy oil, petroleum coke or mixture thereof.

FIG. 19 is a 3D rendering of the reactor. The reactor is made fromIncoloy 800H for added strength at elevated temperatures. The bottomsection of the reactor is made from 2 inch schedule 40 pipe (2.375 inO.D.×0.145 in wall) which is connected to a section of 4 inch schedule40 pipe (4.5 in O.D.×0.237 in wall) that acts as a disengaging zone. Aflat, 800H plate is welded on top of the 4 inch pipe that has ports forthermocouples, gas out and catalyst filling. These pipes/tubing arewelded to the plate and extended out of the hottest zone of the reactorso that stainless steel fittings can be used for their attachmentswithout fear of seizing (oxidation of the internal surfaces of thefittings in air at high temperatures can make them impossible todisassemble).

FIG. 20 shows details of the reactor. The main section of the reactor ismade from 2 inch SCH40 Incoloy 800H pipe. It has an inlet nozzle forfeeding heavy oil that is located approximately 6 inches up from the topof the bottom flange. Details of the inlet are shown in

The reason that the inlet is so far up the main body of the reactor isthat in order to keep the catalyst in the hottest zone of the tubefurnace that encloses the reactor, there must be a screen located about6 inches up from the bottom flange that must protrude from the bottom ofthe furnace in order to remain relatively cool. This prevents the boltsfrom seizing and also permits the use of 316 stainless steel Swagelokfittings for attaching gas lines (stainless steel is not well suited foroperation at temperatures much above 500° C.). The reactor has a verylarge surface area to volume ratio, making heat losses relatively large.Therefore, the main function of the tube furnace is to act as a guardheater. Also, to keep the catalyst bed at 700-900° C. there is a smallhydrogen/oxygen burner located at the bottom of the flange. Hydrogen ismixed with steam or nitrogen and fed into the side of the flange. Oxygenis fed from the bottom. Only enough O₂ to burn the H₂ to generate heatis added; none of the oxygen is used for gasification. This is a way toprovide heat to the reactor.

The catalyst and solid diluent are in the form of irregular particlesbetween about 63 and 106 or alternatively 63 to 225 um, or alternativelystill 106 to 225 um in size. (For example, 63 to 106 um is −140 to +230mesh). These solids are held on a small Inconel 600 frit that issupported on a small cylinder inside the main reactor body. When thereactor is assembled, the annular space between the catalyst/solidsupport cylinder and the inner wall of the 2 inch SCH40 pipe reactorbody is packed with high temperature alumina felt. This configurationkeeps the catalyst in the hot zone of the reactor and out of theannulus. The feed enters through the inlet nozzle.

In examples 3-10 the gas stream product from the reforming step isanalyzed for H₂, CO, CO₂, O₂ and hydrocarbons. The values presented inthe examples below and in the attached figures and the listing of theclaims refer to the composition of on a dry gas basis, or after excesswater has been condensed.

Example 3, Tests with Atmospheric Tower Bottoms: The experiments wererun with Ni catalyst concentrations of 25%, 50% and 75% (by weight)diluted with fluidizable α Al₂O₃. The steam to carbon ratios were variedbetween 1.5 and 13.6. Reforming and regeneration were done at 865° C.and 900° C. respectively at a total system pressure of 50 psig.Reforming lasts about 90-120 minutes, and regeneration lasts about 40-60min, so one cycle is about 3 hours long (e.g. ˜25 cycles in ˜80 hours).

FIG. 10 shows the product gas composition measured using the online gasanalyzer for a single steam reforming and regeneration cycle usingatmospheric tower bottoms (ATB). In all cases the carbon balances were85-95% by mass within experimental error. The steam reforming ATB doesnot require excessively high S/C ratios. The preferred steam/carbonratio for ATB is about 3 and for VTB was about 5.

FIG. 11 shows the results for approximately 30 hours of cycling betweensteam reforming and regeneration using 75 wt % Ni catalyst/25 wt % αAl₂O₃ with S/C=5, at 865° C. and 50 psig. 500 g of the catalyst/diluentmixture (106 to 250 um) were used. ATB was feed to the reactor at 0.408mL/min, or a WHSV of 0.0367 hr⁻¹, for about 90 to 120 minutes. BecauseH₂ returns to the same level with each cycle, there was no catalystdeactivation over the course of the test (26 cycles). If catalystdeactivation were occurring, there would be downward trend with time onstream as less and less hydrogen was produced during each cycle. Theconcentration of hydrogen in the gas remained relatively constant at70-75 vol %.

Example 4, Tests with “Medium” Vacuum Residuum: FIG. 12 shows theresults of 90 steam reforming-regeneration cycles (280 hours) with themedium VTB. Reforming and regeneration were operated at T=865° C. (1589°F.), P=50 psig, Steam/carbon=5. The product of WHSV and time was 0.01 to0.25, which is dimensionless. As before H₂=−70 vol % and there was noevidence of catalyst deactivation As was the case with the ATB, nodeactivation of the Ni catalyst was observed over the course of the 150hours indicating that coke and sulfur deposited on the catalyst wereburned off in the regenerator, and that any metals (e.g. Ni and V)deposited on the catalyst had no measurable effect; Ni and V are themost common metal contaminants found in heavy petroleum fractions. Asbefore, the hydrogen concentration was about 70 volume %.

Example 5, Tests with “Heavy” Vacuum Residuum: FIG. 13 is a gaschromatogram for the “heavy” VTB. This material was a solid at roomtemperature and must be heated to almost 300° F. to melt. Thistemperature is too high to be used in the laboratory liquid feed system(an ISCO syringe pump) so it was diluted with 20 weight percent xylene(which still required heating to be pumped). The heavy VTB is much moretar-like than the medium VTB and has very little in the way of kerosinethrough gas oil hydrocarbons when analyzed by GC. Heavier components arepresent to a larger extent than in the medium VTB. The offset is wherethe background (column bleed) rose to very high levels. FIG. 13 showsthe results for reforming and regeneration at T=865° C. (1589° F.), P=50psig, Steam/carbon=5. The product of WHSV and time was from 0.01-0.25(with time=90 to 120 minutes and 500 g of solids). As before H₂=˜70 vol% and there was no evidence of catalyst deactivation. Because theExxonMobil VTB is not completely fluid until T=150° C., and since wecould not flow at this high of a temperature (limited by the highpressure syringe pump), 20% mixed isomer xylenes were added to make theVTB fluid at room temperature. A carbon mass balance (˜90%) indicatedthat we were not simply reforming the xylene but were in fact reformingExxonMobil VTB. The fact that the hydrogen yield is always around 70% isconsistent with their elemental analyses all containing about the sameamount of carbon.

FIG. 13 shows the results of 34 steam reforming-regeneration cycles (66hours, or 107 minutes per cycle with a WHSV*time=about 0.1) with theheavy VTB. No deactivation of the Ni catalyst was observed over thecourse of the run, and as before, the hydrogen concentration was about70 volume %.

FIG. 14 is a comparison of the gas chromatograms for all three feedsthat were used in Examples 3-5 in the heavy oil reforming process. Allthree chromatograms are shown on the same scale. The ATB (black) has aconsiderable amount of dissolved hydrocarbons in the middle distillateboiling range and only a small amount of higher molecular weightcomponents. In FIG. 14, the peak height of each component is roughlyproportional to its concentration in a given sample. Thus, the mediumVTB (pink) has almost as high a concentration of middle distillatehydrocarbons as the ATB, but the heavy VTB sample (blue) containspractically none. While these results are far from quantitative, theyare useful for comparison purposes and show that the heavy VTB containsonly very high molecular weight hydrocarbons, and therefore, the highconversion we observe when steam reforming heavy VTB is not simply dueto reforming lighter components of the feed, because there are none. Inaddition, the conversions we measure are too high to be a result of justreforming the 20% xylene diluent added to make the VTB fluid.

Example 6: Steam Reforming of Diluted Bitumen: One of the products ofbitumen recovery using steam assisted gravity drainage (SAGD) isso-called “DilBit,” which is short for diluted bitumen. In this case theraw bitumen has been diluted with 30 wt % condensate (lighthydrocarbons) that is co-produced in the SAGD process. The DilBit samplewas obtained from a Canadian oil sands producer. FIG. 15 shows theresult of steam reforming DilBit under the same conditions as the heavyVTB (FIG. 15). As before, the syngas contains about 70 vol % hydrogen(dry basis) and there was no evidence of deactivation over the course of55 cycles (WHSV*time=0.10. This indicates that the technology of thisinvention can be used to generate hydrogen during oil sand bitumenrecovery

Example 7: Steam Reforming Fast Biomass Pyrolysis Oil. Biomass can beconverted into an aromatic oil by very rapid heating in the absence ofair in a process referred to as fast pyrolysis. The advantage of usingfast pyrolysis is that it converts biomass from a low density, moistureladen material into a high energy density, easily transported liquid.The technology of this invention can be used to convert biomass fastpyrolysis oil into hydrogen.

One strategies for biomass conversion into fuels is described by Wrightand coworkers (Wright et al. 2008), where a number of portable,distributed, biomass pyrolysis units are used to generate pyrolysis oil,which is then collected and then shipped via truck or rail to a centralfuel processing plant where the pyrolysis oil is converted into syngasfor fuel synthesis via Fischer-Tropsch, other catalytic processes orhydrogen generation (Wright et al. 2008). Using this approach it hasbeen estimate that Fischer-Tropsch liquids can be produced at a cost ofabout $1.43 per gallon of gasoline equivalent (i.e. same heating value).FIG. 21 shows how the HyRes process could be used to generate H₂ frombiomass fast pyrolysis oil, and FIG. 16 is an example of a singlereforming/regeneration cycle for a steam to carbon ratio of S/C=1,T=865° C. and P=50 psig. FIG. 22, FIG. 23 and FIG. 24 show HyResprocessing of bio-oil for various numbers of cycles and S/C ratios (2, 3and 5, respectively). The various product of the WHSV and time rangeinclude 1.23, 0.343, 0.410, and 0.262. Finally, FIG. 25 is a schematicthat integrates the distributed pyrolysis concept of Wright et al 2008,with the HyRes process.

FIG. 16 shows the results of steam reforming biomass fast pyrolysis oil.The oil was generated from oak. The figure shows only one of severalcycles of reforming followed by catalyst regeneration. Important, thefeedstock is whole, unprocessed oil. Biomass fast pyrolysis oil containssignificant oxygenated organic molecules and is in general much morereactive than atmospheric or vacuum residuum from petroleum refining,which permits operation at very low steam to carbon ratios. The steam tocarbon ratio for the experiment shown in FIG. 16 was unity (S/C=1).

Example 8. Steam reforming C11-C12 paraffinic hydrocarbons (alkanes).The technology of this invention can also be used as an alternative tofixed bed reforming of petroleum naphtha used to generate hydrogen.Conventional fixed bed naphtha steam reforming normally requires the useof special alkali promoted catalysts and high steam to carbon ratios toprevent coke from fouling the catalyst (Twigg 1991).

Norpar 12 is an ExxonMobil product that contains 50% C₁₁H₂₄ and 50%C₁₂H₂₆ and because of the large amount of hydrogen in the feedstock, itis possible to process Norpar 12 with HyRes at much lower steam/carbon(S/C) ratios. The results for steam reforming Norpar 12 at a S/C of3.52, 865° C., 50 psi, 500 g solids (75% nickel catalyst and 25%alumina), Norpar 12 flowrate of 0.687 mL/min and water of 1.6 mL/min,WHSV=0.123 hr⁻¹, cycle time=90 to 120 minutes, and the product ofWHSV*time=0.1845 to 0.246, indicate the H₂ yield is a little larger thanwhat was observed with the heavier feeds, but still around 70 vol %.

FIG. 17 shows that the S/C ratio can be lowered even further toS/C=1.76. This is unexpectedly low for steam reforming, even when usinga methane feedstock, with fixed bed reformers and the reason this ispossible is that the process burns off any coke (and sulfur) thatdeposit on the catalyst during the regeneration step.

FIG. 17 shows the results for steam reforming NorPar 12. NorPar 12 is acommercial product of ExxonMobil that contains approximately 50% C11 and50% C12 alkanes that was used in the laboratory to simulate steamreforming heavy naphtha in the refinery. The experiment was run for ashort time to determine the gas composition, which was essentiallyidentical to the gas compositions produced when reforming ATB, VTB andother hydrocarbon feedstocks, and is essentially identical with the drygas composition predicted from thermodynamic equilibrium calculationsdone using HSC Chemistry form Windows version 6.1. This experimentdemonstrates that the technology of this invention can also be used togenerate hydrogen from petroleum derived naphtha and can be used as analternative to conventional fixed bed naphtha steam reforming.

Example 9: Hydrogen from JP-8 for Fuel Cells. The single fuel for theU.S. military is JP-8, a military grade jet fuel sometimes referred toas logistics fuel and for fuel cells, hydrogen is required. 26 shows theresults for processing JP-8 with HyRes at a S/C=5, T=865° C. and 50 psigand again there was no evidence of irreversible catalyst deactivation.This was a quick test to see if HyRes was suitable for generating H₂ forfuel cells from JP-8, and as a result only 12 cycles were run. The basicidea was that because JP-8 can contain as much as 150 ppm sulfur whichmust be removed. HyRes removes sulfur because the Ni steam reformingcatalyst behaves as a scavenger during reforming. The nickel sulfide issubsequently decomposed to NiO and SOx during regeneration. Thus, HyResis unique in that it simultaneously generates syngas and removes sulfur.Our testing has shown that we can remove sulfur down to levels <5 ppm, aconcentration that can be easily removed using expendable sorbents. Thesuccess of HyRes in processing both Norpar 12 and JP-8 shows that HyResis a violable alternative to fixed bed steam naphtha reforming. Steamnaphtha reforming is used to generate hydrogen in Europe because most ofthe countries mostly use diesel fuel for transportation, have shortagesof natural gas, and thus can use the naphthas produced in the refineryto make hydrogen.

Example 10: Canadian Oil Sand Bitumen. Canadian oil sands (bitumen) arean important unconventional petroleum resource. Normally, bitumen iscoked to produce a synthetic crude oil (missing the 1000+° F. fractionwhich turned into coke) that is then pipelined to the refinery(Probstein and Hicks 1982). The syncrude is then blended withconventional oil so that the atmospheric and vacuum distillationequipment can function properly. One alternative or adjunct to coking toproduce syncrude from bitumen would be to use some of the raw bitumen orDILBIT to make hydrogen for upgrading bitumen to syncrude to reduce theamount of coking required. Hydrogen could also be used to stabilize thesyncrude by saturating olefins produced by coking. We obtained threesamples of bitumen from Sunoco that were classified as follows: 1)DILBIT (Bitumen+30% condensate), 2) Sales Oil (Bitumen+15% condensate)and finally 3) Emulsion (Bitumen/water). We were able to test bothDILBIT and Sales Oil but not Emulsion since it was heterogeneous withlumps of insoluble bitumen in water (basically tar balls). FIG. 15 showsthe results for processing DILBIT with HyRes. DILBIT is bitumen dilutedwith 30% condensate. Condensate is lighter liquid hydrocarbons that areproduced along with bitumen using Steam Assisted Gravity Drainage (SAGD)since some in-situ steam distillation of the material undergroundnaturally occurs. DILBIT is liquid at room temperature and was easy tofeed to the HyRes reactor. The performance of HyRes with DILBIT wasessentially identical to that obtained with refinery residuum ATB andVTB (i.e. 70 vol % H₂ in raw syngas and no catalyst deactivation).

In the above examples 3-10, a reason that the Ni steam reformingcatalyst does not deactivate in the process is that cycling betweenreforming and regeneration removes coke and sulfur from the catalystbefore it can build up to damaging levels. As mentioned earlier,hydrocarbons are steam reformed to syngas in the reformer vessel, andcoke and sulfur that deposit on the catalyst are burned off in theregenerator while is oxidized to NiO. Catalyst from the regenerator (nowNiO) is then reduced back to catalytically active Ni metal by thehydrocarbon feed when it returns to the reformer. In this sense, notonly is the Ni a steam reforming catalyst, but it is also an oxygentransfer material. In a continuous system, balancing the circulationrate between the reformer and regenerator along with appropriate ratesof heavy oil, steam, and air the system can produce syngas continuouslyusing a Ni catalyst. This is in contrast to a fixed bed reformer, whereunless oxygen is added (i.e. PDX) the Ni catalyst will be rapidly coked.

The fate of sulfur in the feedstock: Since ATB and VTB contains all ofthe bottom of the barrel compounds found in crude oil these heavyfeedstocks also contain most of the sulfur (˜1-2 wt %), and since nolong term catalyst deactivation was observed, the sulfur is not stayingon the catalyst. Part of this sulfur tolerance is due to the hightemperature (865° C.) used in the experiments, and the fact that thereis hydrogen in the gas. Both of these help shift the equilibrium towardH₂S+Ni rather than NiS. However, some nickel sulfide form duringreforming and this is the reason that sulfur eventually deactivates thecatalyst in fixed bed steam reformers. In the case of the presentinvention, as long as nickel sulfide does not build up so fast thatregeneration cannot keep up, it will be burned off in the regenerationcycle giving SO₂ while oxidizing the catalyst to NiO. Nickel oxide iscatalytically inactive for steam reforming, but when reforming startsagain, NiO reacts with the hydrocarbons in the feed and is reduced backto catalytically active metallic Ni.

At high temperatures, the high concentration of hydrogen in the productgas prevents significant amounts of nickel sulfide from forming on thecatalyst, as determined by the calculated equilibrium gas composition.For this calculation, the starting concentrations of reactants werechosen to be 1 mole Ni, 0.5 mole H₂S and 100 mole H₂. When performingthermodynamic calculations for normal catalytic applications (such as afixed bed catalyst that is not periodically regenerated), thecalculations are done using much larger concentration of contaminantthan catalyst (e.g. 100:1) to simulate the effect of the catalyst beingexposed to low concentrations of contaminant for long periods of time.HyRes is different in that in an industrial unit that uses circulatingfluidized bed reactor and regenerator, the catalyst is beingcontinuously regenerated.

In the case of the heavy oil gasification/steam reforming experiments inthe lab, we have more catalyst than sulfur (Ni/S>4) because of therelatively low concentration of sulfur in the feed compared to theweight of Ni in the catalyst. For example, for a flow rate of 0.15mL/min of ATB that contains 0.8 wt % S, the rate of sulfur addition is0.001 g/min. In one hour of steam reforming), 0.08 g of sulfur (0.0025gmole) has been fed to the reactor. At the same time there are 125 gramsof R-67-7H catalyst in the reactor and this catalyst contains about 12wt % Ni, which corresponds to 15 grams of Ni (0.266 gmole). If theeffectiveness factor of the catalyst is assumed to be 5% (typical for asteam reforming catalyst—Twigg 1996) there is about 0.012 gmole of Nipresent at the surface. Therefore, there is about 4.5 times as much Nipresent at the surface of the catalyst as there is sulfur in the feedover the course of the one hour gasification/steam reforming step. Whileone sulfur atom could theoretically poison more than one Ni atom(depending on the atomic structure of the catalytically active Nisites), the unexpected lack of deactivation observed in our experimentsindicates that there is not enough sulfur to poison all of the Ni, andthat it does not build up because we periodically burn it off duringregeneration (we observe SO₂ in the regenerator vent gas).

While there are almost 15 grams of Ni in the catalyst in the reactor, at865° C., most of the nickel is present as large metal crystallites (dueto sintering) and only a fraction of the Ni is exposed at the surface toparticipate in catalysis. This fraction is referred to as theeffectiveness factor, which if calculated from experimental data is therate of reaction measured compared to the rate that would be expected ifevery Ni atom were able to participate. Steam reforming catalystsoperate at temperatures around 750-800° C., and at these temperaturestypical effectiveness factors for commercial Ni steam reformingcatalysts are on the order of 5-10% (this is the reason that Ni ispreferred for steam reforming instead of the more active but extremelyexpensive Pt).

The present invention provides a process that allows hydrogen to beproduced in refineries at a cost that is considerably lower thanhydrogen produced from conventional technologies or purchasing hydrogenfrom a third party. This technology converts “bottom of the barrel”residuum into hydrogen and is called HyRes. In the HyRes process,residuum is steam reformed over nickel based catalysts mixed with asolid diluent to produce hydrogen without catalyst deactivation andwithout the need for an oxygen plant, which greatly expands the range offeedstocks that can be used to generate hydrogen. The process steamreforms residuum over nickel based catalysts without catalystdeactivation because the system uses a fluidized bed with periodiccatalyst regeneration with air. Residuum and steam are fed into afluidized bed reactor containing Ni steam reforming catalyst at 865° C.to generate syngas (CO+H₂). Because the process uses contact times onthe order of minutes, not enough carbon (or sulfur) can build up on thecatalyst to cause irreversible deactivation. The catalyst is thenregenerated by burning off the coke and sulfur with air. In thelaboratory, this is done using a single reactor with a nitrogen purgebetween reforming and regeneration steps; however, a preferred processhas a circulating fluidized bed system. Burning off the coke in theregenerator reheats the catalyst to about 900° C. for the next reformingstep (a small amount of residuum, heavy oil or other fuel can be addedto the regenerator to increase the temperature if there is not enoughcoke to reheat the catalyst to 865° C.). The hot nickel catalystreturning to the reforming reactor is present as NiO but is quicklyreduced back into active nickel metal by the hydrocarbons in the feed.

The HyRes process has been reduced to practice using atmospheric towerbottoms (ATB), two types of vacuum tower bottoms (VTB), Norpar 12 (akerosine like solvent), JP-8 aviation turbine fuel and biomass fastpyrolysis oil and condensate diluted oil sand bitumen operating withsteam to carbon ratios of S/C from 1 to 5 (depending on the feed) forhundreds of hours without any catalyst deactivation.

Although the present invention has been described in considerable detailwith reference to certain preferred versions thereof, other versions arepossible. For example, other solid diluents are possible and otherreactor configurations are possible such as two bubbling fluidizedreactors operated alternatively in reforming and regeneration mode; thismode requires the use of valves that can be operated at very hightemperatures. Using circulating fluid beds is less costly and simplerbecause the solids descending in the stand pipes (diagonals in FIG. 1)between the reactors act as gas seals that function as valves (e.g. Jand L-valves as described in Kunii and Levenspiel 1991). Therefore, thespirit and scope of the appended claims should not be limited to thedescription of the preferred versions contained herein.

Any element in a claim that does not explicitly state “means for”performing a specified function, or “step for” performing a specificfunction, is not to be interpreted as a “means” or “step” clause asspecified in 35 U.S.C. § 112 ¶6 or 35 U.S.C. § 112 (f).

What is claimed is:
 1. A heavy oil steam reforming process to produce hydrogen, the process consisting of: providing a heavy oil feedstock; providing a steam feedstock; providing a fuel feedstock; providing an air feedstock; providing two fluidized bed reactors; providing a fluidizable nickel-containing steam reforming catalyst, wherein the fluidizable nickel-containing steam reforming catalyst has a nickel content of from 10-20 weight percent; using the fluidizable nickel-containing steam reforming catalyst in a steam reforming step in a bubbling fluidized reaction, wherein the steam reforming step is performed at about 865 to 900° C. and a pressure of about 50 to 100 psig; using the fluidizable nickel-containing steam reforming catalyst in a regeneration step in a bubbling fluidized reaction, wherein the regeneration step is performed at about 865 to 900° C. and at a pressure of about 50 to 100 psig; allowing the fluidizable nickel-containing steam reforming catalyst to contact the heavy oil feedstock and the steam feedstock in the steam reforming step, wherein the steam reforming step is operated under conditions such that the product of the weight hourly space velocity (WHSV) of the heavy oil feedstock and the time online equals from 0.001 to 10; allowing the fluidizable mixture to contact the air feedstock and the fuel feedstock in the regeneration step to remove sulfur and carbon buildup; repeatedly cycling the fluidizable nickel-containing steam reforming catalyst between the steam reforming step and the regeneration step; and, generating a synthesis gas product stream with at least 25 volume % hydrogen on a dry weight basis and at most 1 volume % nitrogen on a dry weight basis as a product of the steam reforming step.
 2. The process of claim 1, wherein the steam reforming step is operated under conditions such that the product of the weight hourly space velocity (WHSV) of the heavy oil feedstock and the time online equals from 0.01 to 1.64.
 3. The process of claim 1, wherein the steam reforming step is operated under conditions such that the product of the weight hourly space velocity (WHSV) of the heavy oil feedstock and the time online equals from 0.01 to 0.25.
 4. The process of claim 1 further consisting of: providing a fluidizable mixture of the fluidizable nickel-containing steam reforming catalyst and a fluidizable solid diluent, wherein the fluidizable nickel-containing steam reforming catalyst is from 25 to 75 weight percent of the fluidizable mixture.
 5. The process of claim 4, wherein the fluidizable nickel-containing steam reforming catalyst is about 75 weight percent of the fluidizable mixture.
 6. The process of claim 1, wherein the fluidizable nickel-containing steam reforming catalyst has a magnesium aluminate support, and a particle size from 63 to 225 um.
 7. The process of claim 1, further consisting of: generating the synthesis gas product stream with at least 60 volume % hydrogen on a dry weight basis and at most 0.5 volume % nitrogen on a dry weight basis.
 8. The process of claim 1, further consisting of: operating the fluidized bed reactor with essentially no supplemental oxygen during the steam reforming step, other than the oxygen transported in a form of nickel-oxide and that which is contained in the steam and in the heavy oil feedstock.
 9. The process of claim 1, further consisting of operating the steam reforming step with a steam/carbon ratio greater than about
 1. 10. The process of claim 9, further consisting of operating the steam reforming step at a steam-to-carbon ratio between about 1.5 and 13.6.
 11. The process of claim 9, further consisting of operating the steam reforming step at a steam-to-carbon ratio from about 3 to about
 5. 12. The process of claim 1, wherein the heavy oil is long residuum or atmospheric residuum.
 13. The process of claim 1, wherein the heavy oil is vacuum residuum.
 14. The process of claim 1, wherein the fuel feedstock is petcoke.
 15. The process of claim 1 further consisting of: providing a circulating fluidized bed reactor system, the circulating fluidized bed reactor system having a steam reforming fluidized bed and a regeneration fluidized bed, wherein the steam reforming fluidized bed and the regeneration fluidized bed are operably connected to each other.
 16. The process of claim 15, further consisting of: converting the fluidizable nickel-containing reforming catalyst to a nickel-oxide form in the regeneration fluidized bed and allowing the fluidizable nickel-containing steam reforming catalyst to transport to the steam reforming fluidized bed in a continuous looping process.
 17. A fluidized bed hydrocarbon steam reforming process using a regenerable catalyst to produce hydrogen, the process consisting of: providing a hydrocarbon feedstock that has an API gravity between −11 and +54; providing a steam feedstock; providing a fuel feedstock; providing an air feedstock; providing one fluidized bed reactor, the fluidized bed reactor having a bed, wherein the bed is operated in an alternating manner, switching between two steps: a steam reforming step and a regeneration step; providing a fluidizable mixture, the fluidizable mixture comprising a fluidizable solid and a fluidizable nickel-containing steam reforming catalyst; operating the fluidized bed reactor during the steam reforming step at about 865 to 900° C. and at about 50 to 100 psig, and during the regeneration step at about 900° C. and at about 50 to 100 psig, and allowing the fluidizable mixture to contact the hydrocarbon feedstock and the steam feedstock in the steam reforming step for a time such that the product of the weight hourly space velocity (WHSV) of the hydrocarbon feedstock and the time online equals from 0.001 to 10; operating the fluidized bed reactor during the regeneration step at about 900° C., at a pressure of about 50 to 100 psig, and allowing the fluidizable mixture to contact the fuel feedstock and the air feedstock to remove coke and sulfur from the fluidizable mixture; converting the fluidizable nickel-containing steam reforming catalyst to a nickel-oxide form during the regeneration step; generating a synthesis gas product stream with at least 60 volume % hydrogen on a dry weight basis and at most 1.0 volume % nitrogen on a dry weight basis; operating the fluidized bed reactor with essentially no supplemental oxygen for the steam reforming step, other than the oxygen in a form of nickel-oxide from the regeneration step and oxygen contained in the steam feedstock and in the hydrocarbon feedstock; and, operating the steam reforming step with a steam-to-carbon ratio at least 1.0, wherein, the fluidizable nickel-containing steam reforming catalyst has a nickel content of from 10-20 weight percent, a magnesium aluminate support, a particle size from 63 to 225 um.
 18. The process of claim 17, wherein the reforming step is operated under conditions such that the product of the weight hourly space velocity (WHSV) of the hydrocarbon feedstock and the time online equals from 0.01 to 1.64.
 19. The process of claim 17, wherein the reforming step is operated under conditions such that the product of the weight hourly space velocity (WHSV) of the hydrocarbon feedstock and the time online equals from 0.01 to 0.25. 